Method for Hydrocarbon Well Completion

ABSTRACT

A method of completing a hydrocarbon lateral well in a target shale formation. The method uses a data log generated from an optical flow cell assembly to identify areas in the lateral well of high free gas porosity. By evaluating such data, an operator can group “like” rock, determine stage length and variation in stage length, and determine perforation cluster spacing and location. The flow cell assembly can also be used in a completion program to assist in the steering of a lateral well being drilled below the target formation.

BACKGROUND OF THE INVENTION

The present invention relates to a method of hydrocarbon wellcompletion.

SUMMARY OF THE INVENTION

The present invention is a novel method of completing a lateral well ina target shale formation. The method includes the step of providing aflow cell assembly within a flare gas flow line of a rig drilling thelateral well. The gas flow line is in fluid communication with a returnflow line of the lateral well. The assembly comprises a flow cell havingan outer surface, an inner surface, and an internal bore. The flow cellincludes a first aperture and a second aperture. Each of the first andsecond apertures provides an opening to the internal bore. An opticalprobe is detachably mounted on the outer surface of the flow cell. Theoptical probe has a proximal end and a distal end. The optical probe isdisposed through the first aperture in the flow cell so that the distalend of the optical probe is positioned within the internal bore of theflow cell. The optical probe is capable of measuring the velocity of agas flowing through the internal bore of the flow cell. An optical probemounting assembly is detachably mounted on the outer surface of the flowcell. The optical probe mounting assembly encases a portion of theoptical probe. A sensor means is detachably mounted on the outer surfaceof the flow cell. The sensor means includes a sensor array having aproximal end and a distal end. The sensor array is disposed through thesecond aperture in the flow cell so that the distal end of the sensorarray is positioned within the internal bore of the flow cell. Thesensor array includes a temperature sensor and a pressure sensor.

The method includes the step of obtaining a raw point flow velocity dataof the gas flowing in said flow line.

The method includes the step of obtaining a temperature measurement ofthe gas in the flow line.

The method includes obtaining a pressure measurement of the gas in theflow line.

The method includes filtering the raw point flow velocity data to rejecterrant velocity data to obtain filtered raw point flow velocity data.;

The method includes correcting the filtered raw point flow velocity databased on an empirical data of flow meter type and operating conditionsto obtain a bulk velocity data.

The method includes calculating a corrected flow rate for the gas in theflow line based on the bulk velocity data and an internal diameter ofthe flow line.

The method includes using the temperature measurement and the pressuremeasurement for calculating the corrected flow rate for the gas in theflow line.

The method includes calculating a gas volume per foot drilled data basedon the corrected flow rate for the gas and a time measurement.

The method includes using the corrected flow rate to determine an amountof gas in the return flow line.

The method includes generating a data log showing areas of the lateralwell exhibiting high free gas porosity.

The method according to claim 1 wherein said data log is used to groupthe areas according to “like” rock characteristics.

The data log may be used to design a plurality of well completionstages. The data log may also be used to determine the length orvariation in length of the plurality of well completion stages. The datalog may also be used to concentrate the plurality of well completionstages in the areas of the lateral well exhibiting high free gasporosity. The data log may further show areas of low free gas porosityand therefore said to increase the length of the plurality of stages inthe areas of low free gas porosity. The data log may also be used todetermine spacing of a plurality of perforation clusters in each stageof the plurality of well completion stage.

The present invention is also directed to a novel method of drilling alateral well in a target shale formation. The method includes providinga flow cell assembly as described hereinabove within a flare gas flowline of a rig drilling the lateral well. The gas flow line is in fluidcommunication with a return flow line of the lateral well.

The method includes the step of obtaining a raw point flow velocity dataof the gas flowing in the flow line.

The method includes the step of obtaining a temperature measurement ofthe gas in the flow line.

The method includes the step of obtaining a pressure measurement of thegas in the flow line.

The method includes the step of filtering the raw point flow velocitydata to reject errant velocity data to obtain filtered raw point flowvelocity data.

The method includes the step of correcting the filtered raw point flowvelocity data based on an empirical data of flow meter type andoperating conditions to obtain a bulk velocity data.

The method includes the step of calculating a corrected flow rate forthe gas in the flow line based on the bulk velocity data and an internaldiameter of the flow line.

The method includes the step of using the temperature measurement andthe pressure measurement for calculating the corrected flow rate for thegas in the flow line.

The method includes the step of calculating a gas volume per footdrilled data based on the corrected flow rate for the gas and a timemeasurement.

The method includes the step of using the corrected flow rate todetermine an amount of gas in the return flow line.

The method includes the step of generating a first data log showing afirst area of said lateral well exhibiting high free gas porosity.

The method includes using the data log showing the first area of thelateral well exhibiting high free gas porosity to adjust the directionof a drill bit assembly drilling the lateral well.

The method may further includes the steps of generating a second datalog showing a second area of the lateral well exhibiting high free gasporosity, and using the second data log showing the second area of thelateral well exhibiting high free gas porosity to further adjust thedirection of the drill bit drilling the lateral well.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective view of the flow cell assembly of the presentinvention.

FIG. 2 is an exploded perspective view of the flow cell assembly of thepresent invention.

FIG. 3 is a perspective view of the optical probe of the flow cellassembly of the present invention.

FIG. 4 is an exploded perspective view of the valve orientation holdingcell component and locking cam assembly of the present invention.

FIG. 5 is a schematic of the components of the control panel assembly ofthe present invention.

FIG. 6 is a schematic of the flare gas metering system of the presentinvention.

FIG. 7 is a block diagram of the method of calculating a flow rate fromraw point velocity values.

FIG. 8 is a schematic showing the drilling of a lateral well underneatha shale formation.

FIG. 9 is a data log generated by the flow cell assembly of the presentinvention showing areas of high free gas porosity.

FIG. 10 is a data log generated by the flow cell assembly showing theconventional placement design of stage spacing.

FIG. 11 is the data log shown in FIG. 10 but with stage spacing designedin accordance with the method of the present invention.

FIG. 12 is a data log generated by the flow cell assembly showing theconventional grouping of “like” rock.

FIG. 13 is the data log shown in FIG. 12 but with the “like” rockgrouped in accordance with the method of the present invention.

FIG. 14 is a data log generated by the flow cell assembly showing theconventional design of stage length.

FIG. 15 is the data log shown in FIG. 14 but with the stage lengthdesigned in accordance with the method of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The inventor's U.S. patent application Ser. No. 12/786,925, filed May25, 2010, and incorporated herein by reference, describes a noveloptical flow cell assembly. The method described herein uses the datagenerated by the flow cell assembly during hydrocarbon drillingoperations to complete the well for production purposes. By designingthe completion program based on such data, the completion operator canachieve improved hydrocarbon production at each stage while reducingoperational costs. Improved stage placement, stage length andperforation cluster design are achievable using the method of thepresent invention. These and other advantages will be described herein.

With reference to FIG. 1, flow cell assembly 10 includes flow cell 12.Flow cell 12 includes longitudinal portion 14 and flange members 16, 18.Portion 14 has an inner diameter that corresponds with the innerdiameter of the flow line to which flow cell 12 is to be attached. It isto be understood that the inner diameter of flow cell 12 may be made indifferent diameters depending on the inner diameter of the flow linethat will receive flow cell 12. Members 16 and 18 are designed to beaffixed to respective ends of the flow line preferably by boltedconnection with corresponding flanges. When flow cell 12 is connected tothe flow line, flow cell 12 is in fluid communication with the flowline.

Again with reference to FIG. 1, flow cell assembly 10 includes opticalprobe assembly 20. Assembly 20 is detachably affixed to the outersurface of flow cell 12. A bore (not shown) in flow cell 12 permitspassage of optical probe 48 (not shown) from outside flow cell 12 towithin inner bore 22 of flow cell 12. As shown in FIG. 1, assembly 20includes probe cap 24, probe sleeve 26, valve orientation holding cell28, and mounting plate 30. Mounting plate 30 may be mounted onto theouter surface of flow cell 12 by any number of mounting means. Forexample, mounting plate 30 may be affixed to flow cell 12 by bolts orscrews. Valve orientation holding cell 28 is detachably affixed tomounting plate 30 by any suitable mounting means. For example, cell 28many be detachably affixed to mounting plate 30 by bolts or screws. Thedistal end of probe sleeve 26 is slideably positioned within valveorientation holding cell 28. Probe cap 24 may be detachably positionedon the proximal end of probe sleeve 26 when assembly 20 isnon-operational.

FIG. 1 also shows pressure/temperature assembly 32. Assembly 10 mayfunction without assembly 32. Assembly 32 may be detachably affixed tothe outer surface of flow cell 12. A second bore (not shown) in flowcell 12 permits the passage of temperature and pressure sensors intobore 22 of flow cell 12. Assembly 32 includes PT housing cover 34, PTblock 36 (although not shown, a temperature/pressure sensor arrayattaches to PT block 36), second valve orientation holding cell 38 andmounting block 40. PT block 36 includes temperature lead 44 and pressurelead 46. PT block could contain a combined temperature/pressure lead.Mounting plate 40 may be mounted onto the outer surface of flow cell 12by any number of mounting means. For example, mounting plate 40 may beaffixed to flow cell 12 by bolts or screws. Second valve orientationholding cell 38 is detachably affixed to mounting plate 40 by anysuitable mounting means. For example, cell 38 may be detachably affixedto mounting plate 40 by bolts or screws. Mounting plates 30 and 40 maybe identical components. Cells 28 and 38 may also be identicalcomponents.

Mounting plates 30, 40 have radii based on pipe size. Any number ofmounting plates 30 and 40 may be detachably secured to flow cell 12. Forexample, two mounting plates 30 and two mounting plates 40 may bedetachably fixed to flow cell 12. One set of mounting plates 30, 40 maybe positioned on one side of flow cell 12 and the other set of mountingplates 30, 40 may be positioned on the opposite side of flow cell 12. Byincluding multiple mounting plates 30, 40, probe assembly 20 andpressure/temperature assembly 32 may be secured to respective mountingplates 30, 40 in different spatial positions on flow cell 12. This isdesirable because the positioning of flow cell 12 in the flow line couldresult in an obstruction that would prevent the detachable fixation ofassemblies 20, 32 on one of mounting plates 30, 40 but not on the otherset of mounting plates 30, 40 which are situated on the opposite side offlow cell 12.

When probe assembly 20 is not detachably affixed to mounting plate 30,blank cover 42 may be detachably affixed to mounting plate 30. Cover 42may be detachably affixed to mounting plate 30 by any suitable means.For example, cover 42 could be detachably secured to mounting plate bybolts or screws. When probe assembly 32 is not detachably affixed tomounting plate 40, blank cover 42 may be detachably affixed to mountingplate 40. Cover 42 may be detachably affixed to mounting plate 40 by anysuitable means. For example, cover 42 could be detachably secured tomounting plate by bolts or screws. When secured to mounting plates 30,40, cover 42 acts to prevent the passage of fluid such as flare gas fromescaping through the bores in flow cell 12 to the atmosphere.

With reference to FIG. 2, optical probe assembly 20 further includesoptical probe 48, orientation ring 50 and probe socket 52. Probe 48 isdesigned to be inserted through ring 50, through inner bore 54 of sleeve26, through inner bore 56 of cell 28, through inner bore 58 of socket52, through inner bore 59 of mounting plate 30 and through bore 60 inflow cell 12. The distal end of probe 48 sets within inner bore 22 offlow cell 12 at a predetermined position, e.g., ¼″ radius. Sensor array61 is designed to be inserted through inner bore 62 of cell 38, throughinner bore 63 of mounting block 40 and through bore (not shown) in flowcell 12. The distal end of sensor array 61 sets within inner bore 22 offlow cell 12 at a predetermined position.

FIG. 3 illustrates an embodiment of optical probe 48. Probe 48 containsdistal end 64 and proximal end 66. Distal end 64 is designed to bepositioned within inner bore 22 of flow cell 12. Proximal end 66includes heat lead 68 and fiber optic lead 70. Probe 48 may also includeopening 71 through which gas may flow for measuring particle velocity.Probe 48 may be any type of optical probe capable of measuring particlevelocity. Probe 48 may have the following specifications:

-   -   (1) Process temperature −40° C. to +100° C.;    -   (2) Maximum pressure 150 psig;    -   (3) Probe dimensions—diameter ¾″ and length 27″;    -   (4) Pipe size—4″ to 24″;    -   (5) Measurements range—0.1 m/s to 150 m/s;    -   (6) Measurement accuracy—5% (0.1 m/s-1 m/s)        -   2.5% (1 m/s-100 m/s)        -   5% (100 m/s-150 m/s).

Probe 48 may function based on “laser-two-focus” particulatevelocimetry. Probe 48 may include laser light sources capable ofproducing two light beams separated by a fixed distance. Probe 48 mayalso include a lens system for directing the light beams across opening71 (shown in FIG. 3). The light may be concentrated in two active sheetsof light within opening 71. The active sheets may be perpendicular tothe flow direction and separated by a fixed distance. Light is scatteredwhen a particle in the gas flowing through inner bore 22 intersects eachactive sheet. Probe 48 may further include a second lens system and oneor more light detectors. The second lens system may direct the scatteredlight to one or more of the light detectors. The second lens system mayinclude a mirror for reflecting scattered light in a specifieddirection. In this way, probe 48 detects particles flowing in the gas.By measuring the time delay between light scattering occurrences in eachactive sheet, probe 48 may detect the velocity of the gas.Alternatively, probe 48 may function based on “laser-two-beam”particulate velocimetry, in which probe 48 may use light beams tomeasure the velocity of gas particles by sensing the scintillation ofthe light beams caused by flow turbulence.

Correlation calculation is time based and not affected by optical signalamplitude. No field re-calibration is necessary. Flow rate is calculatedin three stages: (1) post processing filters are used to reject errantsamples; (2) flow profile correction based on empiricalcharacterizations for each flow meter type and operating condition usingReynolds number correction; and (3) flow rate is calculated for standardconditions using AGA7/AGA8, as illustrated in FIG. 7. Probe 48 iscommercially available from Photon Control, Inc. under model name FOCUSProbe Optical gas Flow Meter (L2F) and under the model nameLaser-Two-Beam Optical Gas Flow Meter (L2B).

Referring again to FIG. 7, the velocity values detected by probe 48 maybe referred to as the raw point flow velocity values in one embodiment.These values may be filtered to reject errant velocity values resultingin filtered point flow velocity data. This filtered raw point flowvelocity data may then be corrected for flow profiles based on Reynoldsnumber, or other empirical data of the flow profile. The corrected datamay be referred to as the bulk velocity data. From the bulk velocitydata, a corrected flow rate for the gas may be calculated based on theinternal diameter of longitudinal portion 14, and the temperature andpressure measurements taken by sensor array 61. The temperature andpressure measurements may also be used to calculate the Reynolds number.

The use and operation of an optical probe 48 is described inInternational Patent Application Publication No. WO 2006/063463 and inCanadian Published Patent Application CA 2 490 532 A1, which are eachincorporated herein by reference.

As seen in FIG. 4, valve orientation holding cell 28 (and cell 38)includes cover 72, internal isolation valve 74, and back plate 76. Cover72 includes one or more O-rings 78 positioned around bore 56. When probe48 is inserted in probe assembly 20, probe 48 is run past O-rings 78 toisolation valve 74 (e.g., a ball valve assembly). Valve 74 haspreviously been actuated and has sealed flow cell 12. O-rings 78 form aseal around probe 48. Valve 74 is deactivated and no longer seals thepassage to flow cell 12. Probe 48 may then be inserted further to apredetermined point where a portion of distal end 64 of probe 48 setswithin bore 22 of flow cell 12. O-rings 78 provide a seal preventing gaswithin flow cell 12 from escaping to the atmosphere. When removing probe48, probe 48 is pulled out of flow cell 12 to a predetermined positionwhere valve 74 can be actuated while O-rings 78 continue to provide aseal around probe 48. After valve 74 is actuated, probe 48 may beremoved from probe assembly 20.

As seen in FIG. 4, valve orientation holding cell 28 (and cell 38)includes locking cam 80, which is insertable through a bore in cover 72.Cam 80 contains recess 82. Recess 82 houses spring locking pin 84. Campin 86 may be inserted through cam pin hole 88 in locking cam 80.Locking cam 80 locks probe 48 or sensor array of PT Block 36 into afixed position and orientation. The mechanism consists of a round plugwith an orientating groove machined into that fits into a matchingsocket. When the plug is orientated correctly, a cam shaft is able torotate into the plug groove providing for fixed position andorientation. This cam shaft is manually rotated by a hex head. This hexhead is notched in such a manner that when the cam shaft is fullyengaged, the notch becomes engaged with a spring loaded locking pin. Thepin locks the cam shaft assembly in the engaged position so that it cannot become disengaged unless released by the user pushing the lockingpin back into a neutral position thus allowing the hex head to rotatethe cam shaft freely back into the unlocked position.

FIG. 5 shows control assembly 90. Assembly 90 includes control panel 92.Panel 92 includes power supply 94, wireless transmitter 96, flowcomputer 98, heater barrier 100, temperature barrier 102, pressurebarrier 104, intrinsically safe power supply 106, intrinsically safeterminals 108, and other terminals, power, 4-20 output and other devices110.

Computer 98 may be wirelessly accessible so that control over the flowcell assembly may be accomplished remotely. Data generated frommeasuring the gas passing through flow cell 12 may also be wirelesslytransmitted to a remote location or computer for further processing andanalysis. Computer 98 may have the following specifications:

-   -   (1) RS-485        -   (a) Format 8N1        -   (b) Modbus RTU        -   (c) 2400, 9600, and 38,400    -   (2) RS-232        -   (a) Format 8N1        -   (b) Proprietary protocol        -   (c) 38,400 only    -   (3) 4-20 ma analog    -   (4) Probe alarm

As illustrated in FIG. 6, flare gas metering system 112 includes flowcell assembly 10 and control assembly 90. System 112 is incorporatedinto flare line 114, which is part of an oil and gas drilling rig flareassembly. Drilling mud return line 116 carries back fluids from the welland deposits them in separator 118. The fluids contain liquids and gases(some of which are flammable). The liquids exit the bottom of theseparator and the gases exit the top through flare line 114. Flare line114 has an ignition source 120 positioned at the end of the line whichignites the flammable gas exiting line 114. Flow cell assembly 10 hasbeen positioned in fluid communication with the gas passing through line114. Probe assembly 20, and in particular probe 48, is operativelyconnected to control assembly 90 via optical conduit 122 and heatconduit 124. Pressure/temperature assembly 32, and in particular PTblock 36, is operatively connected to control assembly 90 viatemperature conduit 126 and pressure conduit 128. Control assembly 90,namely control panel 92, is operatively connected via power line 130 topower source 132. Power source 132 can be any type of power sourcesupplying power (e.g., electrical) to control assembly 90 and flow cellassembly 10. Power source 132 could be an electrical generator.

It is to be understood that flow cell 12 need not be used as part of thesystem 112. Probe assembly 20 and pressure/temperature assembly 32 (orprobe assembly 20 alone) are capable of being directly connected toflare line 114. A magnetic jig may be used to determine the placement ofmounting plates 30, 40 on line 114. Using the jig, holes may be drilledfor securing mounting plates 30, 40 to line 114. The jig will alsoposition the placement of the bores though line 114 that willaccommodate probe 48 and the sensor(s) of PT block 36. Probe assembly 20and pressure/temperature assembly 32 may be affixed to line 114 asdescribed hereinabove.

Once mounting plates 30, 40 are affixed to flow cell 12 or line 114, theassembly and positioning of probe assembly 20 and pressure/temperatureassembly 32 is straightforward and easily undertaken. With theattachment of valve orientation holding cell 28 and fixation oforientation ring 50 and probe sleeve 26, probe 48 is self-aligning.Probe 48 may be inserted into flow cell 12 or line 114, removed, andreinserted without having to readjust or realign any of the components.Moreover, the depth of insertion of probe 48 within flow cell 12 or line114 is predetermined. The same is true for assembly 32. When cell 38 isfixed to mounting plate 40, PT block 36 with its extended sensor arrayis self-aligning. The senor array may be inserted into flow cell 12 orline 114, removed, and reinserted without having to realign or readjustany of the components.

Optical probe 48 collects light intensity data each time a particlescatters the light in each of the two sheets within inner bore 22 (orflare line 114). Optical probe 48 transmits the light intensity datathrough optical conduit 122 to control panel 92. Pressure/temperatureassembly 32 measures the temperature and pressure of the fluid withinflare line 114. Pressure/temperature assembly 32 transmits thetemperature and pressure measurements through temperature conduit 126and pressure conduit 128 to control panel 92. Computer 92 calculates theraw velocity of the particles based on the time between light scatteringoccurrences. Computer 92 filters the raw velocity values and rejectsoutlier values. Pressure and temperature values and flow profileinformation are used to calculate the flow rate of the gas in flare line114. If pressure/temperature assembly 32 is not included, computer 92may use a predetermined fixed pressure value and temperature value incalculations.

System 112 may be used in well completion operations to increase gasproduction and reduce operational costs. While not limited to anyparticular type of well or formation, the present invention has beenfound useful in the completion of lateral or horizontal wells such asthose completed in what is known as the “Haynesville Shale.”

The particulars of the Haynesville Shale and conventional methods ofcompleting wells in the formation are described in the followingarticles that are incorporated herein by reference:

-   -   (1) Pope, C. D. et al., “Improving Stimulation        Effectiveness—Field Results in the Haynesville Shale,” Society        of Petroleum Engineers, SPE 134165, 2010;    -   (2) Thompson, J. W., “An Overview of Horizontal Well Completions        in the Haynesville Shale,” Society of Petroleum Engineers,        CSUG/SPE 136875, 2010;    -   (3) Pope, Charles et al., “Haynesville Shale—One Operator's        Approach to Well Completions in the Evolving Play,” SPE 125079,        2009.

The Haynesville Shale formation extends over 5-8 million acres inNortheast Texas and Northwest Louisiana. It is thought to be the largestand most active shale gas play in the U.S. The Haynesville Shale is asedimentary rock formation of the Late Jurassic age deposited about 150million years ago. The formation is overlain by the Cotton Valley Groupand underlain by the Smackover limestone. The Haynesville Shale is ablack, organic rich shale that primarily is made up of clay-sizedparticles with small amounts of silt and sand. Estimates have reportedthat 80% of the Haynesville Shale exists as free gas with the remaining20% absorbed on organic surfaces. It has a true vertical depth (TVD)greater than 11,000 feet, temperatures greater than 300° F., andreservoir pressures up to 0.9 psi/ft.

Production of the Haynesville Shale reservoir has involved horizontaldrilling and multistage hydraulic fracturing. Operators strive tocontact as much rock as possible with a fracture network of adequateconductivity. This is done by altering completion techniques such aslateral length, number of stages, and perfection cluster spacing.Hydraulic fracturing designs have also been altered such as multiplestages, diversion job size and the like.

Completion design has treated the reservoir as being composed ofhomogenous rock. For example, during well completion, a lateral well isdrilled through the formation. The lateral can be anywhere from 3,000feet to greater than 5,000 feet. The operator equally spaces the stagesalong the lateral. Each stage may be about 300 feet. The operator putstwo perforation or perf clusters per stage, which are spaced about 85feet from each other. This completion design will exhibit variableperformance among the stages, and even within each stage. Varyingproduction is attributable to the heterogeneous nature of the shale inwhich some formation rock shows increased production and some formationrock shows less production.

It is advantageous to group “like” rock to increase performance. Thegrouping of like rock may be done by gamma ray and mud logs togetherwith the examination of drill cuttings. More intricate methods ofgrouping like rock may involve evaluating the following logmeasurements:

-   -   (1) image log;    -   (2) spectroscopy-based lithology log;    -   (3) sonic log; and    -   (4) pulse neutron log.

The equipment used to acquire image log, spectroscopy-based lithologylog, sonic log, and pulse neutron log data can be cost prohibitive. Theinventor has discovered that data generated from flow cell assembly 10can be effectively used to design well completions in such a way as toincrease production and lower operational costs. The expense associatedwith use of the flow cell assembly 10 is considerably morecost-efficient then the more intricate image log, spectroscopy-basedlithology log, sonic log, and pulse neutron log systems. The flow cellassembly 10 may be used to:

-   -   (1) identify areas of high free gas porosity;    -   (2) group “like” rock;    -   (3) determine stage length and variation in stage length along        the lateral; and    -   (4) determine perf cluster spacing and location.

The Haynesville Shale is heterogeneous having discrete areas of ductileand brittle shales. The brittle shales typically have a high calcitecontent. The flow cell assembly 10 shows these areas of brittle shalesto exhibit high free gas porosity. It is believed that the brittleshales contain natural fractures. When brittle shales are subject tofracturing processes during well completion, the fractures have atendency to stay open as a result of proppant migration into thefractures. In contrast, when ductile shale is fractured, the shale ismore susceptible to closing back over the proppant leading to lessproduction in that area. By using the flow cell assembly 10, areasexhibiting increased gas production, such as those composed of brittleshale, can be identified. The operator can then design the stages withinthe lateral well with such high gas areas in mind. For example, theoperator can employ a shorter stage length with smaller spacing betweenperf clusters within the favorable area. The operator can also employ alonger stage length with increased spacing between perf clusters inthose areas exhibiting low gas production.

The flow cell assembly 10 can also be used to assist in the directionaldrilling of the horizontal lateral wells. For example, if the formationincludes a layer of brittle shale, it is desirable to drill the lateralwell immediately under the layer so that when the well is fractured, thefractures will extend upward, into the layer exhibiting greater gasproduction. If the well bore is drilled to a position below the layersuch that when the well is fractured, the fractures fail to penetrateinto the layer of brittle shale, the fractures are more likely to closeback up due to proppant embedment. The resultant production in this areais therefore diminished. Accordingly, the closer the lateral well, or aparticular stage of the lateral well, is to the bottom of the brittleshale layer, the more likely that gas production will be optimized.

By evaluating the data generated by the flow cell assembly 10, thedriller can use the data to determine where to steer the bottom-holeassembly to position the well. The data from the flow cell assembly 10indicates when the drilled well comes close to or “bumps” the bottom ofthe brittle layer. When the well closes on or bumps the bottom of thebrittle layer, the flow cell assembly 10 will register a small amount ofhigh free gas porosity.

The production results achieved as a result of the use of the flow cellassembly 10 to design the completion program or drill the lateral wellcan be verified by a production log such as a production temperaturelog.

FIG. 8 depicts the drilling of lateral well 134 off of main verticalwell bore 136. Flow cell assembly 10 is shown in fluid communicationwith flare line 138 which is operationally associated with drilling rig140 as would be well known to a skilled artisan. Target formation 142,e.g., shale formation, is shown below well surface 144. The lateral wellcontains drill bit 146. During drilling of lateral well 134, free gasflows back to well surface 144 via lateral well 134, well 136 andthrough flare line 138. Flow cell assembly detects the flow rate of thefree gas returned to well surface 144. Based on this data, flow cellassembly 10 generates a data log exhibiting the areas of high free gasporosity along the length of lateral well 134. Areas exhibiting highamounts of free gas porosity would be those brittle areas, such as dipareas 148 and 150, in closer proximity to lateral well 134.

FIG. 9 shows a data log generated by flow cell assembly 10 during thedrilling of lateral well 134. The section of the lateral represented inthe log extends from 16000 feet to 17000 feet. The graphical datarepresents standard-flow rate MCFD velocity, volume per foot, and gasunits. The log shows discrete areas within this section of lateral well134 exhibiting high free gas porosity indicative of a zone of favorablegas production.

FIG. 10 shows a data log generated by flow cell assembly 10 duringdrilling of lateral well 134 at a section extending from about 13700feet to about 14600 feet. Lines 152, 154, 156, 158 depict conventionalstage spacing design. Stages 152-158 are equally spaced about 300 feetapart.

FIG. 11 shows the same data log as depicted in FIG. 10 but lines 160,162, 164, 166 have been designed based on the analysis of the data.Accordingly, the stage between lines 160 and 162 is in excess of 300feet because this area of lateral well 134 does not show high free gasporosity. The stage between lines 162 and 164 is slightly less than 300feet because this area shows higher free gas porosity. The stage betweenlines 164 and 166 is about 200 feet because this area shows the highestconcentration of free gas porosity.

FIG. 12 shows a data log generated by flow cell assembly 10 duringdrilling of lateral well 134 at a section extending from about 16000feet to about 16950 feet. Lines 168, 170, 172, 174 depict conventional“like” rock groupings where the stages are spaced equidistant from eachother at 300 feet without regard to “like” rock.

FIG. 13 shows the same data log as depicted in FIG. 12 but with lines176, 178, 180, 182 designed based on an analysis of the data to showareas of “like” rock. Accordingly, line 176 has been positioned at about16100 feet and line 178 has been positioned at about 16375 feet to makethe stage inclusive of the “like” rock indicators shown in the log inthis section of lateral well 134. Similarly, line 180 has beenpositioned at about 16645 feet and line 182 at about 16950 feet to makethe stage inclusive of the “like” rock indicators shown in the log inthis section of lateral well 134.

FIG. 14 shows a data log generated from flow cell assembly 10 during thedrilling of lateral well 134 at a section extending from about 12600feet to about 13650 feet. Lines 184, 186, 188, 190 depict conventionstage placement and length every 300 feet.

FIG. 15 shows the data log depicted in FIG. 15 but with lines 192, 194,196 designed based on an analysis of the data, which shows a decreasedor minimal area of free gas porosity. Accordingly, stage length in thislow producing area of lateral well 134 is increased to about 400 feet.

Use and analysis of the data log generated by flow cell assembly 10during well completion operations can achieve the elimination of one ormore stages. Each stage typically costs the operator between $250,000 to$300,00. By eliminating stages, the operator can reduce substantialcompletion costs while maintaining or increasing gas production. Theelimination of stages also results in environmental benefits becauseless fracturing fluids are used. Accordingly, there is less disposal.Use and analysis of the data log will also maximize production byidentifying areas or zones of high free gas porosity so that stages canbe concentrated in such areas and within stages, perf clusters locatedand spaced so as to derive maximum gas capture. Stage length can beincreased on those areas identified by low free gas porosity.

While preferred embodiments of the present invention have beendescribed, it is to be understood that the embodiments are illustrativeonly and that the scope of the invention is to be defined solely by theappended claims when accorded a full range of equivalents, manyvariations and modifications naturally occurring to those skilled in theart from a review hereof.

1.-9. (canceled)
 10. A method comprising: generating a data log from anoptical flow cell assembly within a gas flow line of a rig drilling alateral well, the gas flow line being in fluid communication with areturn flow line of the lateral well, the data log showing areas of thelateral well exhibiting high free gas porosity.
 11. The method of claim10, wherein the optical flow cell assembly comprises: an optical probedisposed within an internal bore of the optical flow cell, the opticalprobe detecting raw point flow velocity data of gas in the gas flowline.
 12. The method of claim 11 further comprising: filtering the rawpoint flow velocity data to reject errant velocity data to obtainfiltered raw point flow velocity data; correcting the filtered raw pointflow velocity data to obtain a bulk velocity data; and calculating acorrected flow rate for the gas in the gas flow line based on the bulkvelocity data and an internal diameter of the gas flow line.
 13. Themethod of claim 12 further comprising: utilizing the corrected flow rateto determine an amount of gas in the return flow line.
 14. The method ofclaim 12, wherein the optical flow cell assembly further comprises: asensor array to receive temperature and pressure measurements, thecorrected flow rate based on at least one of the temperature andpressure measurements.
 15. The method of claim 12, wherein the opticalflow cell assembly is communicatively coupled to a computer forfiltering the raw point flow velocity data, correcting the filtered rawpoint flow velocity data, and calculating a corrected flow rate.
 16. Themethod of claim 10, further comprising: grouping, based on the data log,the areas of the lateral well according to like rock characteristics.17. The method of claim 10, further comprising: designing, based on thedata log, a plurality of well completion stages.
 18. The method of claim17, further comprising: determining, based on the data log, at least oneof a length of the plurality of well completion stages and a variationin length of the plurality of well completion stages.
 19. The method ofclaim 17, further comprising: concentrating, based on the data log, theplurality of well completion stages in the areas of the lateral wellexhibiting high free gas porosity.
 20. The method of claim 17, furthercomprising: determining, based on the data log, spacing of a pluralityof perforation clusters in each stage of the plurality of wellcompletion stages.
 21. A method comprising: generating a data log froman optical flow cell assembly within a gas flow line of a rig drilling alateral well, the gas flow line being in fluid communication with areturn flow line of the lateral well, the data log showing an area ofthe lateral well exhibiting high free gas porosity; and adjusting, basedon the data log, a direction of a drill bit assembly drilling thelateral well.
 22. The method of claim 21, wherein the optical flow cellassembly comprises: an optical probe disposed within an internal bore ofthe optical flow cell, the optical probe detecting raw point flowvelocity data of gas in the gas flow line.
 23. The method of claim 22further comprising: filtering the raw point flow velocity data to rejecterrant velocity data to obtain filtered raw point flow velocity data;correcting the filtered raw point flow velocity data to obtain a bulkvelocity data; and calculating a corrected flow rate for the gas in thegas flow line based on the bulk velocity data and an internal diameterof the gas flow line.
 24. The method of claim 23 further comprising:utilizing the corrected flow rate to determine an amount of gas in thereturn flow line.
 25. The method of claim 23, wherein the optical flowcell assembly further comprises: a sensor array to receive temperatureand pressure measurements, the corrected flow rate based on at least oneof the temperature and pressure measurements.
 26. The method of claim23, wherein the optical flow cell assembly is communicatively coupled toa computer for filtering the raw point flow velocity data, correctingthe filtered raw point flow velocity data, and calculating a correctedflow rate.
 27. The method of claim 21, further comprising: grouping,based on the data log, the areas of the lateral well according to likerock characteristics.
 28. The method of claim 21, further comprising:designing, based on the data log, a plurality of well completion stages.29. The method of claim 28, further comprising: determining, based onthe data log, at least one of a length of the plurality of wellcompletion stages and a variation in length of the plurality of wellcompletion stages.
 30. The method of claim 28, further comprising:concentrating, based on the data log, the plurality of well completionstages in the areas of the lateral well exhibiting high free gasporosity.
 31. The method of claim 28, further comprising: determining,based on the data log, spacing of a plurality of perforation clusters ineach stage of the plurality of well completion stages.